The present application relates to systems and methods for measuring the amount of one phase in a mixture of phases, and more particularly to measuring the amount of water present in crude petroleum oil.
The following paragraphs contain some discussion, which is illuminated by the innovations disclosed in this application, and any discussion of actual or proposed or possible approaches in these paragraphs does not imply that those approaches are prior art.
Background: Water Cut Analyses in Oil Processing
The chemical and physical characterization of crude, partially refined, and fully refined petroleum products is a common practice in the petroleum industry. Characterizations such as compositional and physical property determinations are used for a variety of purposes. One of their more important uses is when they are done in combination with hydrocarbon well testing to assist in optimizing oil production from a single or series of hydrocarbon wells. Another important use is during the transfer of crude petroleum oil, as occurs during the production, transport, refining, and sale of oil. Specifically, it is well know to a person having ordinary skill in the art of petroleum engineering that crude petroleum oil emerging from production wells can contain large amounts of water, ranging from generally about 1% to as high as about 95% water. This value is known as the water cut (“WC”).
Hydrocarbon well optimization methods include adjusting the well operating parameters and employing reservoir stimulation techniques. Decisions in the use of such optimization methods are greatly enhanced if accurate compositional data of the oil is available, both instantaneously and over time. Specifically, in one context of hydrocarbon well production optimization, it is important to be able to determine the amount of water mixed with the crude oil, which is often present as naturally-produced ground water, water from steam injection, and/or well injection water which has become eventually mixed with the oil as a result of a reservoir stimulation process. Once such stimulation process is known as Steam Assisted Gravity Drain stimulation (“SAGD”). Another is the “Huff and Puff” stimulation method where steam is intermittently injected into the reservoir. Different types of stimulation processes can have different phase states upon start-up of the well. Additionally, a result in steam-assist wells is that the salinity of the aqueous phase varies across the steam-assist cycle, usually starting at a low value and climbing throughout the cycle to a high value.
When water is pumped to the surface of the Earth along with the crude oil, producers often attempt to physically separate the water from the oil, because the water can corrode pipes and damage down-stream processing equipment. Further, the water has no value relative to the oil and in-fact can become a disposal or environmental problem wherever it is finally removed. Water-oil “separators” or liquid-liquid decanters are thus often used, before the crude oil is further transported from a well site or tank farm. However, the efficiency of such separators in achieving two pure streams of oil and water is often not 100%, and free water is still frequently entrained in the crude oil as it enters storage, in the range of about 0.10% to about 5%.
Another complicating issue is that gases are almost always present in crude oil as it emerges from the wellhead. This gas is usually natural gas consisting of the lighter hydrocarbon fractions such as methane, ethane, propane, and butane, and can further complicate the chemical and physical assay and characterization of the crude oil stream. Sometimes, carbon dioxide is also present, either naturally-occurring or because it is frequently used in reservoir stimulation. Additionally, gases are often used in varying proportions to lift oil from a well. Gas-liquid separators are often employed to remove the gas fraction and to allow it to be separately measured from the liquid phase. However, again, the efficiency of such separators in achieving two pure streams of liquid and gas is often not 100%, and free gas is sometimes entrained in the crude oil liquid fraction.
The accurate determination of water content and validation of the amount of water in crude oil is particularly important during the taxation of crude oil and the sale of crude oil, where the owner or seller of the oil does not want to pay taxes on water and the customer does not want to pay the price of oil for water. Such determinations and validations can be conducted on-line and off-line during petroleum processing.
The offline method involves physically sampling the stream and analyzing it in a laboratory setting. In the petroleum industry, the sampling is usually done using a composite sampler which automatically opens a sample valve attached to a pipeline at some pre-determined frequency to collect an aggregate sample into a sample container. The objective is to collect a sample which is representative of the entire lot of petroleum under consideration. After collection, the composite sample is usually picked up by a person and taken to a laboratory. The composite sample is then “sampled” to prepare aliquots, or sub-divisions of the composite sample, for each of the various characterizations, or analysis methods, to be used.
Three off-line analytical methods are commonly used for determining the water content of crude oil. These are the centrifuge method, the distillation method, and the titration method. See the American Petroleum Institute (“API”) Manual of Petroleum Measurement Standards, Chapter 10. The distillation and titration methods are relatively accurate, but are plagued by long analysis times and not suitable for use in the field or at the point of sale. The centrifuge method is quicker, but almost always under-reports the amount of water present. The American Society for Testing of Materials has reported the standard analytical errors for water content measurements using the three methods. The repeatability errors are 0.11% for the distillation method (see ASTM D4006), 0.15% for the titration method (see ASTM D4377), and 0.28% for the centrifuge method (see ASTM D4007).
Note that composite petroleum samplers and the associated analytical methods have other kinds of problems and disadvantages other than, for example, meeting a desired accuracy for a given determination. For example, results for composite samplers are typically only available at the end of a batch or a test, and there is no recourse if something goes wrong with the sampling system during the sampling process. At the end of the sampling and analysis, only a single number is available to consider. Additionally, the exposure of personnel to hazardous liquids associated with processing the samples is undesirable. Thus, the petroleum industry has continued to seek other methods that provide the required accuracy, speed, and safety.
Accordingly, the use of rapid on-line instruments such as densitometers, capacitance probes, radio frequency probes, and electromagnetic characterization systems (including those which are referred to, for historical reasons, as “microwave analyzers”) to measure water content of petroleum products is becoming more common. Besides providing increasingly accurate determinations of water content, real time water content results via on-line methods can provide beneficial operational advantages. Knowledge of when water becomes present in petroleum as it is being produced and the magnitude of the quantity of the water may provide an opportunity to remove the water before it reaches a transport pipeline, storage vessel, or shipping tanker. Additionally, the real time data may show if the water is detected in several short periods of time or if it is present across the entire load of the petroleum. Furthermore, real time analyzers may be used as a comparison to the results provide by composite samplers. Finally, on-line measurements of, for example, physical and electrical properties, via instrumentation reduces the need human involvement in the process of characterizing a multiphase fluid mixture.
Background: On-Line Measurements for Density and Electromagnetic Characterizations
On-line densitometers can be used to ascertain the amount of water in petroleum oil. One on-line density method uses a Coriolis meter. This meter can be installed in the pipeline leaving the well or wells on the way to further processing and storage. Coriolis meters measure the density of a fluid or fluid mixture, and its mass flow rate, using the Coriolis effect. Then, calculations can be performed to indirectly determine the water percentage. For example, a Coriolis meter can measure the density of a water-oil mixture, ρmixture, and then perform a simple calculation method to determine the individual fractions or percentages of the water phase and oil phase. By knowing or assuming the density of the dry oil, ρdry oil, and the density of the water phase, ρwater phase, then a water weight percentage, ψwater, can be calculated as follows:ψwater phase=((ρmixture−ρdry oil)/(ρwater phase−ρdry oil))×100
This technique, however, is subject to uncertainty in the validity of the measurement of the percentage water in oil. First, due to natural variations of, for example, the hydrocarbon composition of crude oil, the density of the dry oil can vary significantly from the assumed or inputted value required for the simple calculation. Such a value inputted into a densitometer based on a guess or on history of a given hydrocarbon well. Crude petroleum oils can range from about 800 kilograms per cubic meter (kg/m3) to about 960 kg/m3. Further, the water encountered in hydrocarbon well production is most often saline. This salinity is subject to variability, ranging from about 0.1% by weight salt to about 28%. This results in a variation in the density of the water phase from about 1020 kg/m3 to about 1200 kg/m3. Again, this value would be inputted into a densitometer based on a previously-known laboratory number or on the history of a given well.
Note also that an entrained gas phase, as is sometimes present as described previously, can dramatically affect the density of a petroleum stream as measured by a Coriolis meter, unless a precise correction method is applied for the presence of the gas.
Another technique to determine the water-cut is to use an electromagnetic characterization system (e.g. a “microwave analyzer”), instead of a densitometer, to perform the in-line monitoring of the oil and water mixture.
U.S. Pat. No. 4,862,060 to Scott (the '060 patent), entitled Microwave Apparatus for Measuring Fluid Mixtures and which is hereby incorporated by reference, discloses electromagnetic characterization systems and methods which are most suitable for monitoring water percentages when the water is dispersed in a continuous oil phase.
Note that the change in fluid mixture dielectric properties for a water and oil mixture can be affected by a number of parameters, including not only the percentage of water in oil, but also the individual dielectric constants of the oil phase and the water phase. For example, the dielectric constant of the dry crude oil itself can vary depending on its density and chemical composition. Note that temperature can affect the density of the oil and the water and thus the dielectric properties of each component and the mixture. However, temperature variations can easily be compensated for by using a temperature probe in-contact with the multiphase fluid being characterized to allow referencing to data sets or curves fit to the data sets for different temperatures.
Thus, both the densitometer method (“water-cut by density”) and the electromagnetic characterization method (“water-cut by electromagnetic characterization”) are subject to uncertainties. One approach to dealing with the uncertainty is to simultaneously use both methods to characterize a crude petroleum oil stream for water content. This joint use is practiced commercially. An example is the Compact Cyclone Multiphase Meter (“CCM”) manufactured by Phase Dynamics, Inc. of Richardson, Tex.
When conducting joint densitometry and electromagnetic characterizations of a flow stream of mixtures of water and crude or partially refined petroleum oils, exact values of the electrical and physical properties of the pure water and oil phases are not always known. However, each method can supply estimates of the required values to assist each other in determining water content in petroleum products.
An example of a such a supply of a physical property estimate is disclosed in U.S. patent application Ser. No. 11/273,613, now U.S. Pat. No. 7,334,450, to Bentley N. Scott entitled Methods for Correcting On-Line Analyzer Measurements of Water Content in Petroleum, and is hereby incorporated by reference, and hereinafter referred to as Scott '613. Scott '613 discloses that because a conventional electromagnetic characterization analyzer is usually shop-calibrated across a range of water contents using a dry oil of a known density, the analyzer will report an erroneous water percentage if the dry oil being measured in the field shifts to a different density than that of the original dry calibration oil. The auto-correction method disclosed in Scott '613 ameliorates this problem. Scott '613 teaches that there is 0.03% water-cut by permittivity error introduced for every 1 kg/m3 shift in actual dry oil density from the dry oil calibration density. It discloses that for water-cuts less than about 5%, the density of the actual dry oil can be adequately estimated for use in calculations by the microwave analyzer by assuming the actual dry oil density is equal to the density of the mixture as measured by the densitometer. This assumption results in a maximum error rate of about 0.23% at about 5% water-cut. This error rate compares favorably to the off-line analytical method error rates previously detailed. For well testing the error is more difficult to define and must be done by statistical methods of pulling a population of samples large enough to find a statistical mean and standard deviation. This method is not well defined and the true error is not known since each sample is an independent one and is subject to many errors with equipment and personnel. Since the lab method does not have a known standard error the resulting data is a measure of the reproducibility of the on line analytical equipment and the laboratory methods and handling of the samples.
Background: Crude Oil Phase Behavior and Electromagnetic Characterizations
Still further uncertainty in conducting on-line characterizations of multiphase fluids such as crude oil can be caused by both the physical chemistry of each of the fluids and the multiphase fluid mixture itself. In the case of liquid-liquid mixtures undergoing mechanical energy input, the mixture usually contains a dispersed phase and a continuous phase. So, in the example of water and oil, the mixture exists as either water-in-oil or an oil-in-water dispersion. When such dispersion changes from aqueous phase continuous to non-aqueous phase continuous, or vice-versa, it is said to “invert the emulsion phase”.
Dispersion of one phase into another becomes more stable under mechanical energy input such as agitation, shaking, shearing, or mixing. These resulting physical properties are known as the rheologic properties of the fluids. When the mechanical energy input is reduced or eliminated, coalescing of the dispersed phase can occur, where droplets aggregate into larger and larger volumes. However, these can also be very stable with time depending upon the natural surfactants, densities, temperatures, and salinity of the water. Further, in a substantially static situation (e.g. reduced energy input), heavy phase “settling-out” or stratification can occur under the force of gravity.
Complicated water-oil mixture separation phenomena can sometimes occur as crude oil is pumped from the ground (or from the subsea floor). Because hydrocarbon wells can range in depths to well over 10,000 feet, the oil and any water phase travel in the pipeline for a relatively long period of time before it reaches the wellhead. As the oil and water phases travel to the wellhead, coalescing of each phase can occur, resulting in “slugs” of oil and water emerging from the well rather than a dispersion of, say, small droplets of water in a continuous oil phase. Thus, a well that produces a high level of water can cycle between a span of primarily free water and a span of primarily dry oil. In essence, the vertical column of oil and water in the long well pipe, known as a drill “string”, becomes a vertical oil-water separator. As a result, the water builds up in the drill string and is then pushed through as a water “slug” to the wellhead. This kind of well, due to its behavior, is termed a “slugging” oil well.
A further complicating phase-state phenomena of liquid-liquid mixtures is that stable or semi-stable suspensions of dispersed-phase droplets can sometimes occur. This is usually referred to as an emulsion, which can be either stable or semi-stable. Certain substances are known as emulsifiers and can increase the stability of an emulsion, meaning that it takes a longer time for the emulsion to separate into two phases under the force of gravity or using other means. In the case of petroleum oils, emulsifiers are naturally present in the crude oil. For example, very stable emulsions can occur during petroleum processing, as either mixtures of water-in-oil or oil-in-water as a stable emulsion possible even up to 90% water.
Another complicating phenomenon is that the formation of dispersions and emulsions are sometimes “path-dependent.” Generally, path-dependence exists when the result of a process depends on its past history, i.e. on the entire sequence of operations that preceded a particular point in time, and not just on the current instantaneous conditions. In the case of emulsions, the process of forming the emulsion can be path dependent because the sequence of phase addition, mixing, and energy inputs can affect which phase becomes the dispersed phase and how stable the resulting emulsion is. Thus, if one does not know the history of the multiphase fluid undergoing dispersion or emulsification, one will not always be able to predict the “state” of the dispersion or emulsion, i.e. which phase is continuous and which is dispersed, even if the proportions of the phases are accurately known at a particular point in time.
In electromagnetically-coupled analyzers, whether a dispersion or emulsion is aqueous-continuous or non-aqueous-continuous has a significant effect on the analyzer's measurements. In the case of aqueous-continuous dispersions or emulsions, the conductivity path established by the aqueous-continuous phase causes a significant change in the measured electromagnetic characterizations relative to the same proportion of phases existing as a non-aqueous-continuous dispersion or emulsion. Additionally, further variations in the conductivity of the aqueous-continuous phase caused, for example, by even relatively small changes in salinity, can significantly affect the measured electromagnetic characterization results. Note that when the non-aqueous or oil phase is continuous, no conductivity path is established (because the droplets are not “connected” to form a continuous conducting circuit), Hence (at low RF frequencies) there is no significant effect on the measurements of an electromagnetic characterization analyzer due to aqueous conductivity. Note also that this is only true when the wavelength of the electromagnetic energy is large compared to the emulsion size. When the emulsion size is larger than one eighth of a wavelength the voltage difference across the emulsion can be significant and therefore a correction must be made with respect to the salinity (conductivity at the frequency of measurement) of the water.
As a particular example of the complex behavior of liquid-liquid mixtures and the impact of that behavior on electrical characterizations such as permittivity analyses, consider FIG. 1B. It is a generalized phase diagram 100 of particular crude petroleum oil and a range of aqueous solutions of varying salinity where the fraction of the water phase, XW, is plotted against the frequency, ƒ, as instantaneously read by an electromagnetic characterization microwave analyzer. Note that although the lines are shown as straight lines the relationship between XW and ƒ may not be strictly linear. To illustrate aspects of the complex behavior of liquid-liquid mixtures, consider starting with a pure oil phase that is under-going a given amount of mechanical energy input, as is encountered when such a fluid is pumped through a restricting valve and is experiencing a pressure drop. This starting composition, on the path independent, oil-continuous line 101, is represented by point 102. Then, an aqueous saline solution could be added to the oil phase to form a mixture of water-in-oil, represented by points on line 101. The relationship between the permittivity frequency and the aqueous phase fraction is determined by the line 101. On this line, the multiphase fluid exists as an oil continuous phase with drops of dispersed aqueous phase. Then, increasing amounts of saline solution can continue to be added, up along line 101 to point 104. At point 104, the dispersion progresses along path dependent line 105 to point 106. At point 106, the dispersion inverts to an aqueous phase continuous dispersion, with an accompanying discontinuity in measured permittivity, jumping to a particular permittivity curve depending to a large extent on the salinity of the aqueous phase. Aqueous phase can continue to be added along salinity iso-lines in zone 107 to path-independency transition level 108. At path-independency transition level 108, path dependency is no longer present as the dispersion moves into zone 109. The fraction of aqueous phase can be increased to 1.00, with the permittivity being dependent on both the salinity and the fraction of the aqueous phase.
It should be noted that in certain emulsions, zone 107 may not exist at all, and line 105 might transition directly to zone 109.
In an another example of possible path dependency, the mixture may begin as a point located some where in a high water cut, path independent, salinity-controlling, aqueous-continuous zone 109. Then, the aqueous fraction could be reduced to path-dependency transition level 110, and further reduced to aqueous fraction 112, along the iso-salinity lines within the high water cut, path dependent, aqueous-continuous zone 111. The iso-salinity lines within zone 111 are shown as dashed lines because they represent salinity levels which may be the same as that in zone 107. Additionally, path-dependency transition level 110 may or may not be equal to path-independency transition level 108.
Next, following the iso-salinity lines through zone 107, the dispersion would invert at aqueous fraction 112, and as aqueous fraction is further reduced, the relationship follows oil-continuous, path-dependent line 113 to point 104.
It should be noted that in certain emulsions or dispersions, zone 111 may not exist at all, and line 113 might transition directly from zone 109.
Thus, for the particular crude oil example above as it is mixed in various proportions with a variable salinity aqueous phase, at least three zones of compositional uncertainty can exist for the permittivity of aqueous-continuous dispersions, of which at least two such zones can be path-dependent. Additionally, at least three discrete curves can further relate the permittivity of oil-continuous mixtures, of which at least two such curves can be path dependent. In addition, the oil continuous region is dependant upon the frequency of operation as to whether salinity has any affect on the relationship with water percentage as described earlier with respect to the wavelength of the electromagnetic energy.
Such complex physical chemistry can lead to numerous uncertainties with regards electromagnetic-characterization-based composition determinations. For example, referring again to FIG. 1B of this application, frequency 114 can in-fact represent two different mixture compositions, 116 and 118, depending on how such compositions were formed, as previously described. Additionally, a particular aqueous fraction 119 can correspond to either an aqueous phase dispersion of varying salinity contents, points 120, each having a corresponding permittivity frequency (not shown) or an oil-continuous phase dispersion of a particular frequency 122.
It has been found that these compositional and permittivity frequency uncertainties can be reduced by using a number of methods, depending somewhat on which zone or curve the mixture state resides in or on. For example, to address the problems of phase inversion uncertainties in aqueous and non-aqueous multiphase mixtures, U.S. Pat. No. 4,996,490 to Scott (the '490 patent), entitled Microwave Apparatus and Method for Measuring Fluid Mixtures and which is hereby incorporated by reference, discloses electromagnetic characterization apparatuses and methods for accommodating phase inversion events. For the example of oil and water mixtures, the '490 patent discloses that whether a particular mixture exists as an oil-in-water or a water-in-oil dispersion can be determined by differences in the reflected microwave power curves in the two different states of the same mixture. Therefore, the '490 patent discloses magnetic characterization apparatuses and methods, including the ability to measure microwave radiation power loss and reflection to detect the state of the dispersion. In further embodiments of that invention, methods are disclosed to compare the measured reflections and losses to reference reflections and losses to determine the state of the mixture as either water-in-oil or oil-in-water, which then allows the proper selection and comparison of reference values relating the measured microwave oscillator frequency to the percentage water. An embodiment of the '490 patent is reproduced from that patent in FIG. 1C.
Thus, referring again to FIG. 1B of this application, for water fraction 119, the apparatus and the method of the '490 patent would be able to identify whether the dispersion is in zone 111 or on line 105. When the composition is on line 105, electromagnetic characterization analyzers using the method of the '490 patent are able to accurately determine the aqueous phase fraction. However, within zone 111, the method of the '490 patent would not be able to accurately distinguish which iso-salinity line the composition correlated to in real time, because alone, the method of the '490 patent has no way of knowing the salinity on a real time basis. Thus, the method of '490 alone would not be able to accurately determine water fraction 118.
One method of correcting for the effects of salinity changes is for an operator to manually measure the salinity of the water phase and input the measurement into the analyzer to allow it to select pre-established offset correction factors, based on the inputted salinity and test-generated calibration curves. FIG. 3 and FIG. 4 show exemplary electromagnetic characterization analyzer offset salinity corrections for a generally low range of salinity, of about 0.1% to 8% salinity, and a high range of salinity, of about 8% to about 28% salinity.
A manual determination of salinity is commonly made using a refractometer to measure the refractive index of the water phase. This index is then correlated to % salinity using a pre-established relationship between % salinity and refractive index. The % salinity is then entered into the analyzer as previously described. The pre-established relationship between % salinity and refractive index can be developed by measuring the refractive index of a series of standardized saline solutions to establish a data reference set and equations can be fitted to the data set.
Sometimes, the refractive index of the aqueous phase cannot be easily determined. For example, the aqueous phase may be so turbid as to prevent an accurate reading from being obtained. Or, in the case of an emulsified system, the refractive index cannot be read unless the system is somehow de-emulsified and allowed to separate into a clear-enough aqueous phase to allow a refractive index to be determined.
Such refractive index measurement techniques or other separate salinity measurement techniques are thus inherently unreliable in systems that are susceptible to emulsification and require additional apparatus, further complicating the total measurement system.
Other laboratory methods will analyze the produced water for ionic content and a “total dissolved solids” and the “equivalent NaCl” contents can be determined. Since different salts i.e. NaCl, KCl, etc. all have different conductivities (and these change with electromagnetic frequency) it is difficult to know what number is appropriate to use. Many times the “total dissolved salts” will be used as equivalent NaCl. These numbers are inexact and will lead to real time errors of measurement. In addition, the samples are always at room temperature and do not reflect the conductivity of the ion at the operating temperature of the production fluids.
Thus, solving the problem of accurately ascertaining and validating the amount of each phase in multiphase mixtures is a long felt requiring a more complete and automated solution. More particularly, there is an increasing need for reduction of uncertainty in the characterization of petroleum as the value of petroleum continues to rise.
The present application discloses systems and methods for determining relative proportions of phases in multiphase fluid flow streams. As live characterization data is collected from a multiphase fluid stream, a time series of measurements results. At least some of the extrema of the time series of data are used to generate a corrective transform or transforms.
In some embodiments (but not necessarily all), the disclosed ideas are used at the wellhead of (or slightly downstream from) a producing hydrocarbon well, to estimate the water-cut in as-produced crude petroleum oil.
In some embodiments (but not necessarily all), the disclosed ideas are used at the wellhead of (or slightly downstream from) a producing hydrocarbon well experiencing high water-cut conditions.
In some embodiments (but not necessarily all), the disclosed ideas are used at the wellhead of (or slightly downstream from) a producing hydrocarbon well to improve the accuracy of the characterization of the hydrocarbon well being tested by recalling previously-made characterizations of the same hydrocarbon well upon re-starting or re-testing of the hydrocarbon well.
In some embodiments (but not necessarily all), the disclosed ideas are used at the wellhead of (or slightly downstream from) a producing hydrocarbon well by first removing essentially all of any gas fraction contained in crude petroleum emerging from the wellhead or from a gas-liquid separator.
In some embodiments (but not necessarily all), the time series of measurements includes joint measurements of an electrical property, such as permittivity, and measurements of a physical property, such as density.
The disclosed innovations, in various embodiments, provide one or more of at least the following advantages:                Some of the disclosed inventions provide auto-calibration or correction methods to reduce the uncertainty caused by variable salinity in an aqueous phase of a multiphase fluid flow stream.        Some of the disclosed inventions provide auto-calibration or correction methods to improve the characterization of a multiphase fluid flow stream using a single characterization apparatus with improved accuracy across the complete range of first phase content.        Some of the disclosed inventions provide more accurate physical or electrical property measurements.        Some of the disclosed inventions provide near-real-time reduction of errors and supply more accurate results to aid in near-real-time decision-making, without requiring multiphase fluid flow stream sampling or off-line labwork conducted on such samples and thus eliminating the cost, lost opportunities, and hazards associated with such sampling.        